08 Generator Protection.pdf
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Basics of Generator Protection
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Topic Outline
I.
Gene Ge nera rato torr in in a vi view ew of an Pr Prot otec ecti tion on En Engi gine neer er
II.. II
Typ ypic ical al Ge Gene nera rato torr Pr Prot otec ecti tion on
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Topic Outline
I.
Gene Ge nera rato torr in in a vi view ew of an Pr Prot otec ecti tion on En Engi gine neer er
II.. II
Typ ypic ical al Ge Gene nera rato torr Pr Prot otec ecti tion on
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Generator Configuration
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Generator Configuration
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Generator Configuration
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Generator Configuration
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Generator Connections
Direct Connected
Unit Connected
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Sample Nameplate
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Generator Grounding
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Generator Grounding
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Generator Grounding
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Generator Excitation Control and Generator Capability Excitation Control Basics A generator excitation system provides the energy for the magnetic field that keeps the generator in synchronism with the power system. Two types: those using ac generators as power source and those using transformers.
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Generator Excitation Control and Generator Capability Excitation Control Basics
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Generator Excitation Control and Generator Capability Excitation Control Basics Aside from maintaining synchronism of the generator, the generator also: Affects the amount of reactive power that the generator may absorb or produce. Increasing the excitation current results in increase reactive power output. Decreasing the excitation current results in decrease reactive power output, extreme case loss of synchronism will occur.
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Generator Excitation Control and Generator Capability Generator Watt/VAR Capability
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Generator Excitation Control and Generator Capability
P-Q Curve
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Protection Requirements
To detect faults on the generator
To protect generator from the effects of abnormal power system operating conditions
To isolate generator from system faults not cleared remotely
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Faults and Abnormal Conditions
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Sample Generator Protection
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Stator Phase Protection
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Stator Phase Protection This is achieved by:
Differential Relaying (87)
Turn Fault Protection (for split-phase generators)
Overcurrent (thermal)
RTDs
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Differential Protection
High-Speed protection that can detect three-phase, phase to phase and double-phase to ground faults.
Single-line to ground faults are not normally detectable unless its neutral is solidly or low-impedance grounded.
Will not detect a turn-to-turn fault within the same phase
Both sides of the generator should be of the same ratio, rating, connected burden, and preferably have the same manufacturer.
It could be high-impedance type, low-impedance type and selfbalancing differential schemes.
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Differential Protection
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Differential Protection
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Overcurrent Protection
For small generators this may be the only protection applied.
With solid earthing, it will provide some protection against earth faults
For a single generator, CTs must be connected to neutral end of stator winding. Generator 3
~
50/51
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Overcurrent Protection Some helpful points in setting overcurrent relays: From C37.102-2005: Use IOC and TOC unit having an EI characteristic. IOC is set to 115% FLC and is used to torque-control TOC unit TOC unit is set to 75%-100% FLC and a time settings operating 7sec @ 218% FLC or coordinate with downstream relay. From ABC’s of Overcurrent Protection: Set protection above FLC and above decrement curve in the lowest decade. Set protection below overload curve. Set protection to intersect with the decrement curve in the second lowest decade.
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Overcurrent Protection
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Stator Ground Protection
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Stator Ground Protection This is achieved by (depends on the grounding method):
Differential Relaying (87N)
100% Stator Ground Fault Protection using voltage relays
Overcurrent
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Stator Ground Fault Protection
Stator grounding determines the generator performance during fault conditions.
If solidly grounded, it will deliver very high current to a SLG fault at its terminals with no neutral voltage shift, therefore equipment damage is severe.
If ungrounded, it will deliver a negligible amount current during a SLG fault at its terminals with fill neutral voltage shift which could cause failure of generation equipment insulation.
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Stator Ground Fault Protection
Because of this, stator windings on major generators are grounded in a manner that will reduce fault current and overvoltages and yet provide a means of detecting the ground fault condition quickly enough to prevent burning of core iron.
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Low-Impedance Stator Grounding
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Low-Impedance Stator Grounding
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Low-Impedance Grounding
The grounding resistor or reactor is selected to limit the generator contribution to an SLG fault to range of currents between 200A and 150% of rated load current.
Supplementary protection is provided by using 87N
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Low-Impedance Grounding
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High-Impedance Grounding
High-resistance generator neutral grounding uses a distribution transformer with a primary rating greater than or equal to the line-to-neutral voltage rating of the generator and a secondary rating of 120 or 240V.
Power dissipated in the resistor is approximately equal to the reactive volt-amperes in the zero-sequence capacitive reactive of the generators, windings of any transformers connected to generator terminals.
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High-Impedance Grounding An
SLG fault is generally limited to 3 to 25 primary
amperes.
Others only uses resistor aside from transformers but the fault current is limited to 5A.
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High-Impedance Grounding
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Overvoltage/Overcurrent Schemes
59G works on fundamental frequency (3V0)
Typically set at 5V
Measures maximum at terminal fault and decreases at faults moves toward the neutral
Must be coordinated with other protection that works on ground faults 39
100% Stator Ground Fault Protection
59G can provide protection for only about 80% to 95% of the stator windings.
This is due to generator construction imperfections and subsequent small amounts of zero-sequence current that will flow in the generator ground.
This small amount of zero-sequence current makes it impossible for conventional ground fault detection relays to remain selective when set too low low..
Additional
ground fault protection is required. required.
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100% Stator Ground Fault Protection
Protection can be done using:
Third-harmonic voltage-based techniques
Neutral or residual subharmonic voltage injection
Third-harmonic voltages components are present at the terminals of nearly every machine to varying degrees; they arise due to the nonsinusoidal nature of rotor flux and vary based in machine design and manufacturer.
These voltages are used in detecting faults on the generator to provide protection.
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100% Stator Ground Fault Protection
3rd-harmonic voltage is dependent on operating conditions of the generator. There is a point where the 3 rdharmonic is zero. For a ground fault at the neutral, 3 rd harmonic decreases as fault approaches to neutral For a ground fault at the terminal, 3rd harmonic decreases as fault approaches to the terminals. The 3rd harmonic levels should be measured with the generator connected and disconnected from the transformer before enabling 3 rd harmonic protection. 42
100% Stator Ground Fault Protection Third-Harmonic Undervoltage
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100% Stator Ground Fault Protection Third-Harmonic Undervoltage
Since for a fault near the neutral, the level of thirdharmonic voltage at the neutral decreases.
Therefore undervoltage relay at the neutral could be used.
It is tuned at 180Hertz to measure third harmonic.
Set to overlap with 59G settings.
Sometimes, it is supervised with OC relay, real or reactive power and breaker contact.
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100% Stator Ground Fault Protection Third-Harmonic Overvoltage
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100% Stator Ground Fault Protection Third-Harmonic Overvoltage
Since for a fault near the neutral, the level of thirdharmonic voltage at the terminal increases.
Therefore overvoltage relay (59T) at the terminal could be used.
It is tuned at 180Hertz to measure third harmonic.
Set to overlap with 59G settings.
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100% Stator Ground Fault Protection Third-Harmonic Comparator Technique
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100% Stator Ground Fault Protection Subharmonic Injection Schemes
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Field Fault Protection
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Field Fault Protection
Field circuit is an isolated DC system.
Insulation failure at a single point:
No fault current, therefore no danger
Increase chance of second fault occurring
Insulation failure at a second point:
Shorts out part of field winding
Heating
Flux distortion causing violent vibration of rotor
Desirable to detect presence of first earth fault and give an alarm. 50
Field Fault Protection
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Field Fault Protection
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System Backup Protection
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System Backup Protection Backup protection is divided into:
Phase-fault protection
(21) Distance relays
(51V) Voltage controlled/restraint overcurrent relays
Earth fault protection
(51G) Ground OC Relays
Sometimes (46) is also used as backup which provides unbalanced fault protection backup. 54
System Backup Protection
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System Backup Protection 51V
Use of simple OC relay is not recommended.
Voltage Restrained
Operating characteristics is continuously varied. depending on measured volts.
Voltage Controlled
Relay switches between fault characteristic and load characteristic depending on measured volts.
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System Backup Protection Distance Phase Backup Protection
Most common type of phase system backup protection.
Two zones are applied with mho characteristic.
If the generator is connected where there is no phase shift ( wye-wye transformer or directly connected), the relay will accurately measure the impedance
If the generator is connected to delta-wye transformer, where there is phase shift, auxiliary PT is required to compensate the phase shift.
If no aux. PT, use compensator distance relay. 57
System Backup Protection Distance Phase Backup Protection Setting Guidelines
Set the impedance relay to the smallest of the three following criteria: 120 percent of longest line (with infeed). If the unit is connected to a breaker-and-a-half bus, this percent is calculated using the length of the adjacent line. 50 to 66.7 percent of load impedance (200 to 150 percent of the generator capability curve) at the machine-rated power factor. 80 to 90 percent of load impedance (125 to 111 percent of the generator capability curve) at the relay maximum torque angle (MTA).
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System Backup Protection
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System Backup Protection Backup Ground Protection
Backup ground protection is set to pickup for ground faults at the end of all lines out of the station
Set to coordinate with the slowest ground fault protection on the system.
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Abnormal Frequency Protection (81)
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Abnormal Frequency Protection
Stable system is when Power Input = Power of all loads + Losses in the system
When there is a change between the this relationship, abnormal system frequency arises.
Underfrequency condition occurs as a result of sudden reduction in input power
Overfrequency condition occurs as a results sudden loss of load or key interties exporting power.
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Abnormal Frequency Protection
Major considerations associated with operating a generating plant at an abnormal frequency:
Protection of equipment from damage that could result from operation at an abnormal frequency.
Prevention of inadvertent tripping of the generating unit for a recoverable abnormal frequency condition that does not exceed the plant equipment design limits.
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Abnormal Frequency Protection Conformance to IEC 60034:2007
Some turbine generators are designed to accommodate frequency voltage characteristics from IEC 600343:2007, Rotating Electrical Machines-Part 3.
This standard requires generators to deliver continuously rated output at the rated power factor over the range of ±5%
in voltage and
±2%
in frequency. (61.2 Hz and
58.8Hz)
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Abnormal Frequency Protection Conformance to IEC 60034:2007
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Abnormal Frequency Protection Conformance to IEC 60034:2007
The standard recommends that operation outside the shaded are “be limited in extent, duration and frequency of occurrence.”
The manufacturer could therefore impose time restrictions for example below 95% or above 103% of rated frequency.
Goal of frequency protection scheme is to return the frequency to the continuous IEC operating frequency range (98% to 102%). 66
Abnormal Frequency Protection
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Overexcitation and Overvoltage Protection (24 / 59)
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Overexcitation and Overvoltage
Overexcitation occurs whenever the ratio of the voltage to frequency (V/Hz) applied to the terminal exceeds design limits. IEEE standards have established the ff. limits:
Generators, 1.05pu at the output terminals (generator base)
Transformers, 1.05pu at the terminals at rated load or 1.1pu at no load
These limits apply unless manufacturers state otherwise.
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Overexcitation and Overvoltage
When V/Hz ratios are exceeded, saturation of the magnetic core of the generator or connected transformers can occur, and stray flux will be induced into non laminated components.
Note that overexcitation protection on a generator or its it s connected transformer is different from field overexcitation.
Excessive overvoltage of a generator will occur when the level of dielectric field stress exceeds the insulation capability. 70
Overexcitation and Overvoltage
Not all overvoltage condition will be detected by V/Hz relay.
It is general practice to provide overvoltage relaying to alarm, or in some cases, trip the t he generators from these high dielectric stress levels.
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Overexcitation and Overvoltage
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Overexcitation and Overvoltage
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Overexcitation and Overvoltage
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Loss-of-Excitation Protection (40)
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Loss-of-Field Protection
Causes of loss-of-field:
Accidental trip of field breaker
Field open circuit
Field short circuit
Voltage regulator system failure
Loss of supply to excitation system
For most generators, the unit will overspeed and operate as an induction generator. It will supply power but takes reactive power from the system. 76
Loss-of-Field Protection
On loss-of-field, apparent impedance of fully loaded machine travels from loaded value in the 1 st quadrant to the 4th quadrant close to –X axis at value just above the direct –axis transient reactance (about 2-7 seconds).
Final impedance point depends on initial load, varies between Xd’/2 at full load to direct-axis synchronous reactance Xd at no load.
Locus of impedance trajectory depends on system impedance
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Loss-of-Field Protection
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Loss-of-Field Protection For small and less important machines, a single-zone offset mho is used to detect this condition. For larger machines, two-zone offset mho is used.
Smaller Circle (#1)
Diameter of 1.0 pu impedance on machine base
“Small” “almost instantaneous” time delay
Offset equal to –X’d/2
Larger Circle (#2)
Diamter of Xd
Time delay of 30-60 cycles
Offset equal of –X’d/2 79
Loss-of-Field Protection Two-zone Offset Mho characteristic
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Negative-Sequence Current(46)
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Negative-Sequence Protection
In the real world, I A does not necessarily equal to I B and IC
Unbalances are caused by:
System asymmetries
Unbalanced loads
Unbalanced system faults
Open phases
Produce negative-sequence currents-induce a double frequency current
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Negative-Sequence Protection I2 crosses
the air gap, appears in rotor as double-frequency
current
Flows in rotor surface, non magnetic wedges
Severe overheating, melting of wedges into air gap
Standards permits 5-10% of I2
Short-time limits expressed as
2 = ,
where K is a design
constant
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Negative-Sequence Protection
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Negative-Sequence Protection
Short-time values apply for 120 seconds or less. Beyond 120 seconds, the continuous capability should be used.
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Negative-Sequence Protection
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Anti-motoring or Reverse Power (32R)
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Generator Motoring Occurs when the energy supply to the prime mover is cut off while the generator is still on the line. A primary indication of motoring is the flow of real power into the generator. Estimated power required to motor the idling prime mover is:
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Out-of-Step Protection (78)
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Out-of-Step Protection
When a fault occurs on the power system, the generator can begin to accelerate due to differences in the mechanical power into the generator and the electrical power at the generator terminals.
If the fault is not cleared quickly, this acceleration will result in the generator rotor voltage advancing beyond 90 degrees with respect to the generator terminal voltage.
At
this point, power flow into the generator and the rotor angle
will continue to advance until is aligned with the next pole. This is known as slipping a pole or loss of synchronism. 90
Out-of-Step Protection
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Out-of-Step Protection
Adverse Effects
High peak currents and off-frequency operation (slipping)
Winding stresses
Pulsating Torques
Mechanical resonances
Standard generator protection will not detect loss-of-sychronism
Standard transmission line protection will not detect loss-ofsynchronism
If electrical center is between the GSU into the generator, out-ofstep protection should be applied at the machine terminals 92
Out-of-Step Protection Determination of Electrical Center
Electrical center is the point in the system where the impedance between the sources is equal.
Electrical center = (Xd’ + Xt + Xs) / 2
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Out-of-Step Protection
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Out-of-Step Protection
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Out-of-Step Protection
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Inadvertent Energization
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Inadvertent Energization When an offline generator is energized (w/o field) on turning gear or coasting to a stop, the generator behaves as an induction motor and can be damaged within a few seconds
Causes:
Operating Errors
Open Breaker Flashovers
Control Circuit Malfunctions
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Inadvertent Energization When an offline generator is energized (w/o field) on turning gear or coasting to a stop, the generator behaves as an induction motor and can be damaged within a few seconds
Causes:
Operating Errors
Open Breaker Flashovers
Control Circuit Malfunctions
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Inadvertent Energization The following protection elements may detect or can be set to detect inadvertent energizing:
Loss of Field Protection
Reverse Power
Negative-sequence overcurrent
Breaker Failure
System backup
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Inadvertent Energization Inadvertent energization protection needs to be in service when the generator is out of service.
Dedicated protection:
Directional Overcurrent
Frequency Supervised Overcurrent
Distance Relay
Voltage Supervised Overcurrent
Auxilliary Contact-Enabled Overcurrent Overcurrent Supervised by Multiple Elements 101
Loss-of-Potential (60)
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Loss-of-Potential
Loss of the voltage transformer (VT) signal can occur because of a number of cases, most commonly fuse failure.
It could be VT or wiring failure, an open circuit in the draw-out assembly, an open contact due to corrosion or blown fuse
Such loss can cause protective relay misoperation or failure or generator voltage regulator runaway, which can lead to generator overexcitation
It is important to detect loss-of-potential condition, sometimes called, fuse loss (60FL)
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Loss-of-Potential
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Synchronism Check and Auto Synchronizing (25)
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Synchronism Check and Auto Synchronizing
Synchronism Check
Checks the generator system frequency, voltage magnitude, and phase angle be in alignment
Typical parameters call for no more than 6RPM error, 2% voltage magnitude difference, and no more than 10 deg phase angle error before closing the breaker
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Synchronism Check and Auto Synchronizing
Auto Synchronizing (25A)
Checks the generator system frequency, voltage magnitude, and phase angle be in alignment
It involves sending voltage and speed raise and lower commands to the voltage regulator and prime governor.
When the system is in synchronism, the autosync relay is sometimes designed to send a close command in advance of the zero phase angle error to compensate for breaker close 107
Synchronism Check and Auto Synchronizing
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Tripping Modes
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Tripping Modes
Simultaneous Tripping
Provides the fastest means of isolating the generator
Used for all internal generator faults and severe abnormalities in the generator protection zone.
Generator Tripping
Does not shutdown the prime mover and is used where it may be possible to correct the abnormality quickly, permitting a rapid reconnection of the machine to the system.
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Tripping Modes
Unit Separation
Initiates only the opening of generator breakers
Recommended when maintaining the unit auxiliary loads connected to the generator is desirable.
Sequential Tripping
Used for prime mover problems where high-speed tripping is not a requirement.
1. turbine valves, 2. generator breakers 3. field breaker and load transfer of loads.
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Tripping Modes
These tripping scheme must be review and applied according to the present generator application
Selection would depend on the ff:
Type of prime mover
Impact of the sudden loss of output power on the electrical system and prime mover
Safety to personnel
Operating experience
Management of unit auxiliary loads during emergency shutdown. 112
Tripping Modes
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Sample Tripping Modes
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Sample Logic
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Sample Logic
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Sample Logic
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Sample Logic
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